Systems and Methods for Vertical Depth Control During Extended-Reach Drilling Operations

ABSTRACT

Systems and methods for vertical depth control during extended-reach drilling operations include extending a length of a wellbore to locate a directional drilling assembly at a selected location within an intermediate portion of a subsurface region and detecting a detected pressure at the selected location. The methods further include determining an expected pressure at the selected location, comparing the detected pressure to the expected pressure, and adjusting an orientation of the directional drilling assembly based, at least in part, on the comparison. The expected pressure may be determined based, at least in part, on a reference pressure that was detected previously within the intermediate portion of the subsurface region. The systems include extended-reach drilling operations and/or directional drilling assemblies that include and/or are associated with controllers that are programmed to perform the methods.

CROSS REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application No. 61/657,361, filed Jun. 8, 2012, the complete disclosure of which is hereby incorporated by reference.

FIELD OF THE DISCLOSURE

The present disclosure is directed generally to systems and methods for vertical depth control during extended-reach drilling operations, and more particularly to systems and methods that utilize reference pressure within a subsurface region for improved depth control.

BACKGROUND OF THE DISCLOSURE

Extended-reach drilling (ERD) operations often involve drilling a wellbore that includes a vertical or angled portion and that also includes a horizontal portion. The vertical or angled portion may extend between a surface region and a reservoir, while the horizontal portion may extend within the reservoir. Generally, accurate placement of the horizontal portion of the wellbore within and/or near the target depth, or target vertical depth, may be desirable. Accordingly, it may be desirable to locate the horizontal portion at a target depth within the reservoir, in order to decrease a potential for premature water and/or gas production from the reservoir and/or to permit standoff to and/or from reservoir boundaries. This target depth also may be referred to herein as a target total vertical depth (TVD).

Traditional measurement while drilling (MWD) surveying techniques rely upon accelerometers, gravitometers, magnetometers, and/or gyroscopes, hereinafter collectively referred to as surveying techniques, traditional surveying techniques, MWD surveying techniques, and/or standard MWD survey techniques, to measure an angle of inclination and/or an angle of azimuth of the wellbore at a given point in time during the drilling operation. These traditional MWD surveying techniques have inherent uncertainties associated with the use thereof. As an illustrative, non-exclusive example, traditional MWD surveying techniques only may be able to determine the angle of inclination and/or the angle of azimuth at any given time to within a threshold value and/or within a threshold accuracy. Thus, an uncertainty of a TVD that is determined thereby may be an integrated and/or cumulative uncertainty that increases with a length of the wellbore.

As an illustrative, non-exclusive example, standard MWD surveying techniques may have a TVD uncertainty of ±1.0-1.5 m for every 1000 m of wellbore length. Even under the best conditions and utilizing the most stringent conventional quality control techniques, this uncertainty only may be reduced to approximately ±0.6 m for every 1000 m of wellbore length.

While this level of uncertainty may be sufficient under certain conditions and/or in certain drilling operations, it may preclude, or at least hinder, the effective use of extended-reach drilling operations under other conditions and/or in other drilling operations. As an illustrative, non-exclusive example, an extended-reach drilling operation may be utilized to produce a wellbore with a length of 12,000 m (or more) and may target a reservoir that is (or that includes an oil column and/or an oil-filled region that is) only 10-20 m thick. Under these conditions, traditional MWD surveying techniques would have a vertical uncertainty within the reservoir of ±7-18 meters, which is significantly larger than a vertical uncertainty that may be needed to accurately place the wellbore within, or at least near, a target TVD within the reservoir (such as a vertical center, or other desired depth, of the reservoir). Thus, there exists a need for improved systems and methods for vertical depth control during extended-reach drilling operations.

SUMMARY OF THE DISCLOSURE

Systems and methods for vertical depth control during extended-reach drilling operations are disclosed herein. The methods may include extending a length of a wellbore to locate a directional drilling assembly at a selected location within an intermediate portion of a subsurface region and detecting a detected pressure at the selected location. The methods further may include determining an expected pressure at the selected location, comparing the detected pressure to the expected pressure, and adjusting an orientation of the directional drilling assembly based, at least in part, on the comparison. The expected pressure may be determined based, at least in part, on a reference pressure that was detected previously within the intermediate portion of the subsurface region. The systems may include extended-reach drilling operations and/or directional drilling assemblies that include and/or are associated with controllers that are programmed to perform the methods.

In some embodiments, the orientation of the directional drilling assembly may be adjusted to adjust a trajectory of the wellbore within the subsurface region. In some embodiments, the adjusting may include increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being more than the expected pressure and/or decreasing the angle of inclination responsive to the detected pressure being less than the expected pressure. In some embodiments, the systems and methods further may include determining an orientation adjustment magnitude.

In some embodiments, the systems and methods may include detecting the reference pressure. In some embodiments, the wellbore is a second wellbore and the reference pressure is detected within a first wellbore that is spaced apart from the second wellbore. In some embodiments, the reference pressure is detected at a reference location. In some embodiments, the systems and methods further include calculating a reference depth of the reference location.

In some embodiments, the systems and methods may include detecting a plurality of reference pressures at a plurality of reference locations. In some embodiments, the systems and methods further may include determining a plurality of reference depths of the plurality of reference locations. In some embodiments, the systems and methods further may include determining a pressure vs. depth profile within the intermediate and/or reservoir portion of the subsurface region.

In some embodiments, the systems and methods may include repeating at least a portion of the methods a plurality of times to extend the wellbore from the surface region to the wellbore. In some embodiments, the systems and methods further may include extending the wellbore within the reservoir.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic representation of illustrative, non-exclusive examples of an extended-reach drilling operation that may include and/or be utilized with the systems and methods according to the present disclosure.

FIG. 2 is a plot of depth vs. pressure that may be obtained from and/or utilized with the systems and methods according to the present disclosure.

FIG. 3 is a flowchart depicting methods according to the present disclosure of controlling a directional drilling assembly.

DETAILED DESCRIPTION AND BEST MODE OF THE DISCLOSURE

FIG. 1 is a schematic representation of illustrative, non-exclusive examples of an extended-reach drilling operation 20 that may include and/or be utilized with the systems and methods according to the present disclosure. As illustrated in solid lines in FIG. 1, a drilling rig 30 may be utilized to drill a first well 40 that extends between a surface region 22 and a reservoir 80 that is located within a subsurface region 24. Reservoir 80 also may be referred to herein as a subterranean formation 80 and/or as a target formation 80. Reservoir 80 may include a gas-filled region 82, which may include a gas 83, and an oil-filled region 84, which may contain oil 85 and which also may be referred to herein as a pay zone 84. One or more upper formations 26 may be located in an intermediate portion 25 of subsurface region 24 that extends between surface region 22 and reservoir 80. In addition, one or more lower formations 28 may be located vertically below reservoir 80.

As illustrated in FIG. 1 at 86, subsurface region 24 may define a fluid barrier between upper formation 26 and gas-filled region 82, which may permit gas 83 that is present within gas-filled region 82 to remain therein. In addition, subsurface region 24 further may define a gas-oil interface 88, which also may be referred to herein as a gas-oil contact region 88, and may define a boundary between gas-filled region 82 and oil-filled region 84. Similarly, subsurface region 24 also may define an oil-water interface 90, which also may be referred to herein as an oil-water contact region 90, and may define a boundary between oil-filled region 84 and lower formation 28.

Extended-reach drilling operation 20, and/or drilling rig 30 thereof, may utilize a directional drilling assembly 70 to drill a first wellbore 42, which also may be referred to herein as a wellbore 42, that is associated with and/or defines first well 40. Directional drilling assembly 70 may permit control of an orientation of wellbore 42 and/or of a path, or trajectory, of wellbore 42 as it extends through subsurface region 24. As illustrated in FIG. 1, reservoir 80 may be spaced apart from drilling rig 30 in a horizontal direction 60 and also in a vertical direction 62. As such, directional drilling assembly 70 may be directed and/or steered during operation of drilling rig 30 such that wellbore 42 extends along a desired path, or trajectory, within subsurface region 24, such that a portion of wellbore 42 enters, or is located within, reservoir 80, and/or such that a portion of wellbore 42 extends within and/or proximal to a desired portion of reservoir 80.

Directional drilling assembly 70 may utilize measure while drilling (MWD) surveying techniques and/or equipment 71 to estimate and/or approximate the trajectory and/or TVD of a given point along a length of wellbore 42 within subsurface region 24. However, and as discussed, the positional uncertainty of the wellbore associated with the use of MWD surveying techniques increases with increased length of wellbore 42. Thus, and for long wellbores 42, for large distances between drilling rig 30 and reservoir 80 in horizontal direction 60, for large distances between drilling rig 30 and reservoir 80 in vertical direction 62, and/or for small thicknesses, or depths, 92 of reservoir 80, gas-filled region 82, and/or oil-filled region 84, it may be difficult to accurately locate wellbore 42 within a desired portion of oil-filled region 84 (such as may be defined by a target total vertical depth (TVD) 64 of a portion of wellbore 42 that extends within oil-filled region 84).

Thus, and as illustrated in FIG. 1, conventional extended-reach drilling operations may utilize a pilot leg 44 to determine a location of gas-oil interface 88 and to determine a location of oil-water interface 90. Subsequently, the pilot leg may be plugged and a separate production leg 46 may be drilled at and/or near target TVD within oil-filled region 84. In general, such a procedure may decrease and/or eliminate the measurement uncertainty associated with the portion of wellbore 42 that extends within intermediate portion 25 of subsurface region 24 and thereby may permit more accurate location of production leg 46 within the desired portion of oil-filled region 84 (and/or at target TVD 64). However, drilling of pilot leg 44, plugging of pilot leg 44, and subsequent drilling of production leg 46 may be a labor- and/or time-intensive process that may significantly increase an overall cost associated with producing oil 85 from reservoir 80, especially when a plurality of wells are to be drilled within the reservoir and the above-described procedure must be repeated for each of the wells.

With this in mind, the systems and methods according to the present disclosure are configured to collect pressure data, such as through the use of a pressure gauge 72. This pressure data may include any suitable pressure that is, is indicative of, and/or is related to, a pressure at a given point within subsurface region 24 prior to formation of wellbore 42 therein. Thus, the pressure data may be different and/or distinct from a hydrostatic pressure that may be measured within a drilling mud that fills a wellbore during drilling of the wellbore. As an illustrative, non-exclusive example, and when upper formation 26 includes one or more water sands formations, the pressure data may include the pressure of the water that is present within the water sands layer. As additional illustrative, non-exclusive examples, this pressure data also may include the pressure of gas 83 that may be present in gas-filled region 82, the pressure of oil 85 that may be present in oil-filled region 84, the pressure of any suitable fluid that may be present within upper formation 26, and/or the pressure of any suitable fluid that may be present within lower formation 28.

Pressure gauge 72 may be associated with drilling rig 30 and/or may be configured to collect pressure at or near directional drilling assembly 70 and/or at or near a terminal end of a drill string 74 that may include directional drilling assembly 70 and that may be utilized to form wellbore 42. This may include collecting pressure data during the drilling of first well 40 (including during the drilling of pilot leg 44 and/or of production leg 46 thereof) and utilizing this pressure data during drilling of a second, or subsequent, well 50 that also may extend between surface region 22 and oil-filled region 84. This process may decrease a time and/or expense associated with drilling second well 50 (such as by elimination of a need to drill pilot leg 44), thereby decreasing an overall cost associated with producing gas 83 and/or oil 85 from reservoir 80. As illustrative, non-exclusive examples, utilizing the pressure data during drilling of second well 50 may decrease the time needed to drill the second well by at least 20%, at least 30%, at least 40%, at least 50%, or at least 60%. As a more specific but still illustrative, non-exclusive example, consider the time and expense savings when the systems and methods disclosed herein are utilized to reduce a drilling time for a 12,000 meter-long well from 120 days to 60 days. The drilling may be performed and/or controlled manually and/or using any suitable controller 96, which may be programmed to control the operation of extended-reach drilling operation 20 using methods 200, which are discussed herein.

FIG. 1 illustrates extended-reach drilling operation 20 as including two wells, namely, first well 40 and second well 50. However, it is within the scope of the present disclosure that extended-reach drilling operation 20 may be utilized to form more than two wells within subsurface region 24 and/or that subsurface region 24 may include more than two wells. As illustrative, non-exclusive examples, subsurface region 24 may include a plurality of wells including at least 3 wells, at least 4 wells, at least 5 wells, at least 6 well, at least 8 wells, at least 10 wells, or more than 10 wells.

When subsurface region 24 includes a plurality of wells, it is within the scope of the present disclosure that the systems and methods disclosed herein may be utilized to form a portion, or all, of the plurality of wells. As an illustrative, non-exclusive example, the pressure data that is collected during the drilling of first well 40 may be utilized during the drilling of a portion, or all, of the subsequent wells that may be drilled within the subsurface region. As another illustrative, non-exclusive example, pressure data that is collected during drilling of a given well (which may or may not be first well 40) may be utilized during drilling of a portion, or all, of the wells that may be drilled subsequently to drilling of the given well.

FIG. 2 is an illustrative, non-exclusive example of a plot of depth (as determined from MWD surveying techniques) vs. pressure that may be obtained from and/or utilized with the systems and methods according to the present disclosure. In FIG. 2, solid, or filled, symbols represent pressure data that may be collected during the drilling of first well 40, while open, or unfilled, symbols represent pressure data that may be collected during the drilling of second well 50 (as also illustrated in FIG. 1).

As illustrated in solid circles in FIG. 2, one or more pressure measurements may be collected at one or more depths (as determined from MWD surveying techniques) within intermediate portion 25 of subsurface region 24 during the drilling of first well 40. These one or more pressure measurements may be utilized to determine an upper formation pressure gradient 100 (i.e., a slope of the line that connects the solid circles), which also may be referred to herein as, and/or may be, a pressure gradient 100 and/or as a pressure vs. depth profile 100. When subsurface region 24 includes only a single upper formation 26 and/or when subsurface region 24 includes a plurality of upper formations 26 that are in fluid communication with one another, these pressure measurements may fall on, or nearly on, a straight line, as illustrated.

However, and when subsurface region 24 includes a plurality of upper formations 26 that are hydraulically isolated from one another, a pressure step change may be observed upon transitioning from one layer to the next. This pressure step change may be at least substantially similar to a pressure step change 110, which is discussed in more detail herein, and the systems and methods according to the present disclosure may include determining a respective pressure gradient in at least a portion and/or all of the plurality of hydraulically isolated upper formations 26.

Additionally or alternatively, it also is within the scope of the present disclosure that, as discussed in more detail herein, the pressure measurements within a given formation and/or within a plurality of hydraulically connected formations may not fall on or otherwise define a straight line. Thus, in some implementations of the systems and/or systems according to the present disclosure, a curve and/or other non-linear mathematical function may be fit to the pressure measurement data and later utilized to determine the expected pressure at a given location within the subsurface region. As an illustrative, non-exclusive example, a density of a fluid that is located within a given upper formation 26 (or, similarly, reservoir 80 and/or lower formation 28) may vary with depth within the formation. As such, pressure vs. depth profile 100 (or, similarly, pressure vs. depth profile 120, 130, and/or 140 that are discussed herein) may not be described accurately, or as accurately, by a straight line (than a curve or other non-linear expression), the pressure measurements may not fall on the straight line, and/or another mathematical function (such as a curve or other non-linear expression) may be utilized to describe the pressure vs. depth profile.

As discussed herein with reference to FIG. 1, subsurface region 24 may include a fluid barrier 86 that fluidly isolates gas-filled region 82 from upper formation 26. This fluid barrier may permit a discontinuity, or step change, in pressure upon moving from the upper formation to gas-filled region 84 due to evolution of gas 83 from oil 85 and resultant pressurization of the gas-filled region. As such, and upon extending wellbore 42 into gas-filled region 82, pressure step change 110 may be observed (as illustrated in FIG. 2). Subsequently, and as illustrated in solid triangles in FIG. 2, one or more pressure measurements may be collected within gas-filled region 82. These pressure measurements may be utilized to determine a gas-filled region pressure gradient 120 (i.e., a slope of the line that connects the solid triangles), which also may be referred to herein as, and/or may be, a pressure gradient 120 and/or as a pressure vs. depth profile 120.

While FIGS. 1-2 illustrate subsurface region 24 as including fluid barrier 86 and gas-filled region 82, it is within the scope of the present disclosure that subsurface region 24 may not include fluid barrier 86 and/or that subsurface region 24 may not include gas-filled region 82. When subsurface region 24 does not include fluid barrier 86 and/or gas-filled region 82, a depth vs. pressure plot that is obtained therefrom may not include pressure step change 110.

Subsequently, wellbore 42 may be extended into oil-filled region 84. As illustrated in solid squares in FIG. 2, one or more pressure measurements may be collected within oil-filled region 84. These pressure measurements may be utilized to determine an oil-filled region pressure gradient 130 (i.e., a slope of the line that connects the solid squares), which also may be referred to herein as, and/or may be, a pressure gradient 130 and/or as a pressure vs. depth profile 130.

Wellbore 42 then may be extended into lower formation 28. As illustrated in solid diamonds in FIG. 2, one or more pressure measurements may be collected within lower formation 28. These pressure measurements may be utilized to determine a lower formation pressure gradient 140 (i.e., a slope of the line that connects the solid diamonds), which also may be referred to herein as, and/or may be, a pressure gradient 140 and/or as a pressure vs. depth profile 140.

Additionally or alternatively, and distinct from traditional pilot leg 44 that is discussed herein with reference to FIG. 1, the systems and methods according to the present disclosure further may include turning wellbore 42 and/or pilot leg 44 thereof back toward surface region 22 and extending the wellbore in an upward direction through oil-water interface 90, through oil-filled region 84, through gas-oil interface 88, through gas-filled region 82, through fluid barrier 86, and/or into upper formations 26, as illustrated in dotted lines in FIG. 1 at 45. This additional length of wellbore 42, which may be referred to herein as pilot leg extension 45, may permit additional pressure measurements to be obtained at additional depths within lower formations 28, oil-filled region 84, gas-filled region 82, and/or upper formations 26, thereby increasing the accuracy of pressure gradients 100, 120, 130, and/or 140.

Additionally or alternatively, and as illustrated in solid lines in FIG. 1, wellbore 42 may not extend through reservoir 80 until formation of pilot leg extension 45. As such, pressure measurements within lower formations 28, oil-filled region 84, gas-filled region 82, and/or upper formations 26 only may be collected during formation of pilot leg extension 45.

Additionally or alternatively, a depth of gas-oil interface 88, as well as a pressure that may be associated therewith, may be approximated and/or calculated from an intersection point between the line (or curve) that extends through the solid triangles of FIG. 2 and the line (or curve) that extends through the solid squares. Similarly, a depth of oil-water interface 90, as well as a pressure that may be associated therewith, may be approximated from an intersection point between the line (or curve) that extends through the solid squares of FIG. 2 and the line (or curve) that extends through the solid diamonds (as may be defined by pressure vs. depth profile 140).

Under these conditions, drilling of pilot leg extension 45 also may permit verification of the depth and/or pressure of gas-oil interface 88 and/or verification of the depth and/or pressure of oil-water interface 90. As an illustrative, non-exclusive example, the depth of oil-water interface 90 may be calculated as discussed above. Then, as pilot leg 45 passes through the calculated depth of the oil-water interface (as determined by MWD surveying techniques), the pressure may be measured and compared to the calculated pressure. A similar procedure may be utilized to verify the location of gas-oil interface 88.

During and/or subsequent to formation of first well 40, a value of target TVD 64 and/or a pressure that is associated therewith also may be measured and/or calculated. As an illustrative, non-exclusive example, wellbore 42 may be extended to target TVD 64 and the pressure that is associated therewith may be measured. As another illustrative, non-exclusive example and subsequent to determining the pressure and depth of gas-oil interface 88 and the pressure and depth of oil-water interface 90, a point along the line (or curve) that connects the solid squares of FIG. 2 may be selected, with the depth that is associated therewith corresponding to target TVD 64 and the pressure that is associated therewith corresponding to the pressure at the target TVD. This may include selecting any suitable point, such as a midpoint between gas-oil interface 88 and oil-water interface 90.

Subsequent to drilling pilot leg 44 and/or pilot leg extension 45, and as discussed herein, the pilot leg may be plugged and a production leg 46 may be drilled at and/or near target TVD 64 within oil-filled region 84, as illustrated in dash-dot lines in FIG. 1. This may include drilling production leg 46 and/or controlling a depth of production leg 46 in any suitable manner, including in a manner that is at least substantially similar to the drilling of second well 50, which is discussed in more detail herein.

Subsequent to formation of first well 40 and/or subsequent to collection and/or determination of some and/or all of the above pressure data, second well 50 may be drilled within subsurface region 24. As illustrated in dashed lines in FIG. 1, second well 50 may be separate, distinct, and/or spaced apart from first well 40 but may be constructed to extend within the same reservoir 80 as first well 40.

Drilling of second well 50 may include extending a length of, or drilling, a second wellbore 52, which also may be referred to herein as a wellbore 52, that is associated therewith. As discussed in more detail herein, this drilling (and/or the operation of a directional drilling assembly 70 that is associated with the formation of second well 50) may be manually and/or automatically controlled, regulated, and/or directed based, at least in part, on the pressure data that was collected during the drilling of first well 40.

As an illustrative, non-exclusive example, and subsequent to determining the pressure at target TVD 64 (during formation of first well 40), drilling of second well 50 may include extending wellbore 52 progressively deeper into subsurface region 24 until a terminal end of wellbore 52 is at, or near, the determined pressure at target TVD 64. Then, wellbore 52 may be extended in horizontal, or at least substantially horizontal, direction 60, such as to maintain wellbore 52 at, or within a threshold distance of, target TVD 64 and/or such as to maintain a pressure that is measured within wellbore 52 at, or within a threshold pressure of, the determined pressure at target TVD 64.

As another illustrative, non-exclusive example, and while wellbore 52 is being extended progressively deeper into subsurface region 24, a pressure at one or more selected locations, or points, along a length of wellbore 52 may be measured and compared to an expected pressure, with the expected pressure being determined and/or calculated based upon the pressure data that was measured during formation of first well 40, which also may be referred to herein as a reference pressure. As an illustrative, non-exclusive example, the expected pressure may be calculated using pressure vs. depth profiles 100, 120, 130, and/or 140 to calculate the expected pressure at the selected location along the length of wellbore 52.

As another illustrative, non-exclusive example, the selected location along the length of wellbore 52 may be selected such that a depth thereof (as determined using MWD surveying techniques) corresponds to and/or is the same as a depth at which a pressure measurement was taken during formation of first well 40. Under these conditions, the expected pressure may correspond to and/or be the pressure that was measured at a corresponding depth (as measured using MWD surveying techniques) during formation of first well 40.

Under certain conditions, there may be a difference between the measured pressure and the expected pressure. This pressure difference may be caused by the inherent uncertainty associated with the use of MWD surveying techniques to calculate wellbore depth, as discussed in more detail herein. This uncertainty may be cumulative and/or integrated over a length of the wellbore and thereby increases with increasing wellbore length. In contrast, and while the pressure measurements that are discussed herein also may include inherent pressure uncertainty, this inherent pressure uncertainty may be due to the accuracy and/or precision of pressure gauge 72. As such, this pressure uncertainty is not cumulative and/or integrated over (or does not increase with) the length of the wellbore and is therefore constant, or at least substantially constant, for all of the pressure measurements.

Thus, and while an exact, actual, and/or real depth of a given pressure measurement may not be exactly known (since this depth is calculated via MWD surveying techniques), pressure measurements may be utilized to compare two depths that were determined by MWD surveying techniques in a relative fashion, which also may be referred to herein as MWD-determined depths. As an illustrative, non-exclusive example, a given MWD-determined depth in first well 40 may have a corresponding MWD-determined depth uncertainty of several meters, or more, associated therewith. In contrast, a pressure that is measured at the given depth may have a pressure uncertainty of, for example, 7 kilopascals (kPa). Assuming that the given point is located within a water-bearing formation with a density of 1 gram per cubic centimeter, this pressure uncertainty may correspond to a depth uncertainty of approximately 0.7 meters and may be independent, or at least substantially independent, of the wellbore length.

As such, and for long wellbores (i.e., wellbores of a few thousand meters in length or more), the depth uncertainty associated with drilling the wellbore to a target formation pressure may be significantly less than the depth uncertainty associated with drilling the wellbore to a target MWD-determined depth. Thus, the use of first well 40 to establish one or more reference pressures within subsurface region 24 and control of the drilling of second well 50 using these pressures may permit accurate location of the depth of second wellbore 52 relative to the depth of first wellbore 42, permitting accurate targeting of target TVD 64 without the need to drill pilot leg(s) in the second well.

If the measured pressure differs from the expected pressure (or differs by more than a threshold amount) an adjustment to the drilling process may be made. As an illustrative, non-exclusive example, and if the measured pressure is greater than the expected pressure, an actual depth at the selected point along the length of wellbore 52 may be greater than expected and/or greater than an actual depth of wellbore 42 at a corresponding MWD-determined depth. Thus, an angle of inclination 54 of directional drilling assembly 70 within wellbore 52 may be increased. As another illustrative, non-exclusive example, and if the measured pressure is less than the expected pressure, the actual depth at the selected point may be less than expected and/or less than the actual depth of wellbore 42 at the corresponding depth. Thus, the angle of inclination of the directional drilling assembly may be decreased. This process may be repeated any suitable number of times during the drilling of second well 50 and may permit extension of wellbore 52 within subsurface region 24 to target TVD 64 without the need to drill pilot leg 44, without the need to drill pilot leg extension 45, without the need to plug pilot leg 44, and/or without the need to drill production leg 46 subsequent to drilling and plugging of pilot leg 44.

As an illustrative, non-exclusive example, and as illustrated in dashed lines in FIG. 2, drilling of second well 50 may include extending wellbore 52 to a first location 150 that has a first MWD-determined depth and a first pressure associated therewith. In the illustrative, non-exclusive example of FIG. 2, the first pressure is greater than the expected pressure (i.e., the pressure of first well 40 at the first depth as indicated by the solid line and solid symbols in FIG. 2), indicating that the actual depth of second well 50 is greater than the actual depth of first well 40 for the same MWD-determined depth for the two wells (i.e., that the angle of inclination of the directional drilling assembly may be too small). Thus, the angle of inclination may be increased, and the drilling process continued to a second location 154 that has a second depth and a second pressure associated therewith. At second location 154, the second pressure is approximately equal to the expected pressure. Thus, the angle of inclination may not be adjusted.

The drilling process may be continued to a third location 158 that has a third depth and a third pressure associated therewith. At third location 158, the third pressure may be less than the expected pressure, indicating that the actual depth of second well 50 is less than the actual depth of first well 40 at the same MWD-determined depth (i.e., that the angle of inclination of the directional drilling assembly may be too great). Thus, the angle of inclination may be decreased and the drilling process continued to a fourth location 162. This process may be repeated any suitable number of times, such as at a fifth location 166, a sixth location 170, a seventh location 174, etc. until the measured pressure corresponds to the expected pressure at target TVD 64. Then, wellbore 52 may be extended in a horizontal, or at least substantially horizontal, direction within gas-filled region 82 (as illustrated in FIG. 1). This may include repeating the pressure measurements and repeating the adjustments to the angle of inclination while wellbore 52 is being extended within the oil-filled region to maintain wellbore 52 within a threshold depth difference of target TVD 64 (or to maintain the detected pressure within a threshold pressure difference of the expected pressure at target TVD 64).

The systems and methods disclosed herein have been discussed in the context of extended-reach drilling operations 20 that may be utilized to produce oil from a thin, or relatively thin, oil-filled region 84. As illustrative, non-exclusive examples, and with reference to FIG. 1, the oil-filled region may define a thickness 92, which also may be referred to herein as (and/or may be) an average thickness 92, of at least 0.1 meters (m), at least 0.25 m, at least 0.5 m, at least 0.75 m, at least 1 m, at least 2 m, at least 3 m, at least 4 m, at least 5 m, at least 6 m, at least 7 m, at least 8 m, at least 9 m, at least 10 m, at least 12 m, at least 14 m, at least 16 m, at least 18 m, or at least 20 m. Additionally or alternatively, thickness 92 also may be less than 40 m, less than 35 m, less than 30 m, less than 28 m, less than 26 m, less than 24 m, less than 22 m, less than 20 m, less than 18 m, less than 16 m, less than 14 m, less than 12 m, or less than 10 m.

Similarly, wellbores 42/52 may define any suitable wellbore length and/or wellbore trajectory between surface region 22 and reservoir 80. As illustrative, non-exclusive examples, the wellbore length may be at least 2 kilometers (km), at least 3 km, at 4 km, at least 5 km, at least 6 km, at least 7 km, at least 8 km, at least 9 km, at least 10 km, at least 11 km, at least 12 km, or at least 13 km. Additionally or alternatively, the wellbore length may be less than 30 km, less than 25 km, less than 20 km, less than 19 km, less than 18 km, less than 17 km, less than 16 km, less than 15 km, less than 14 km, less than 13 km, less than 12 km, less than 11 km, or less than 10 km.

Additionally or alternatively, it is also within the scope of the present disclosure that the systems and methods disclosed herein may be utilized to increase the accuracy, or vertical depth accuracy, of any suitable drilling operation. This may include drilling operations that are not extended-reach drilling operations (such as drilling operations with a wellbore length of less than 2 km) and/or drilling operations that produce oil from a thick, or relatively thick, oil-filled region 84 (such as oil-filled regions with an average thickness of greater than 40 m).

As used herein the phrase “measurement while drilling surveying” and/or the phrase “MWD surveying techniques” may include measuring and/or calculating a location of directional drilling assembly 70 within wellbore 42/52 in any suitable manner using any suitable MWD surveying equipment. As an illustrative, non-exclusive example, drill string 74 and/or directional drilling assembly 70 thereof may include and/or be associated with any suitable accelerometer, gravitometer, gyroscope, and/or magnetometer that may be configured to determine and/or measure any suitable angle of inclination and/or angle of azimuth thereof to calculate a location of the directional drilling assembly and/or a trajectory of wellbore 42/52 within subsurface region 24. This may include accelerometers, gravitometers, gyroscopes, and/or magnetometers that are operatively attached to drill string 74, operatively attached to directional drilling assembly 70, conveyed into the wellbore via a wireline, and/or dropped into the wellbore.

Directional drilling assembly 70 may include any suitable structure that may be configured to drill a non-linear and/or non-vertical wellbore 42/52 and/or that may be configured to be controlled to control an orientation, path, and/or trajectory, of wellbore 42/52 within subsurface region 24. As illustrative, non-exclusive examples, directional drilling assembly 70 may include and/or be any suitable whipstock, mud motor, drill bit, and/or rotary steerable system.

It is within the scope of the present disclosure that wellbore 42/52 may define, and/or that directional drilling assembly 70 may be utilized to form, create, and/or define, any suitable orientation, path, and/or trajectory within subsurface region 24. As an illustrative, non-exclusive example, at least a portion (and optionally a plurality of portions, or regions) of wellbore 42/52 may be vertical, or at least substantially vertical. As another illustrative, non-exclusive example, at least a portion (and optionally a plurality of portions, or regions) of wellbore 42/52 may be horizontal, or at least substantially horizontal. As yet another illustrative, non-exclusive example, at least a portion (and optionally a plurality of portions, or regions) of wellbore 42/52 may be deviated and/or may define any suitable angle of inclination 54 within the subsurface region. This may include wellbores 42/52 that define a single vertical or deviated portion that extends (at least substantially) between surface region 22 and reservoir 80 followed by a single horizontal (or at least substantially horizontal) portion that extends (at least substantially) within reservoir 80. Additionally or alternatively, this also may include wellbores 42/52 that may define curved and/or arcuate shapes within subsurface region 24, wellbores 42/52 that may define “S” shapes within the subsurface region, and/or wellbores that may define a plurality of inflection points within the subsurface region.

It is also within the scope of the present disclosure that wellbores 42/52 may enter reservoir 80, gas-filled region 82, and/or oil-filled region 84 at any suitable angle and/or at (or from) any suitable portion thereof. As an illustrative, non-exclusive example, wellbores 42/52, pilot leg 44, pilot leg extension 45, and/or production leg 46 may enter a top, or upper surface, of reservoir 80 (as illustrated in FIG. 1 for wellbore 52 and/or as illustrated for wellbore 42 when reservoir 80 includes the dashed portion). As another illustrative, non-exclusive example, wellbores 42/52 may enter a side, or edge, of reservoir 80 (as illustrated in FIG. 1 for production leg 46 entering reservoir 80 when the reservoir does not include the dashed portion). As yet another illustrative, non-exclusive example, wellbores 42/52 may enter a bottom, or lower surface, of reservoir 80 (as illustrated in FIG. 1 by pilot leg extension 45).

Pressure gauge 72 may include any suitable structure that may be selected and/or configured to measure pressure within subsurface region 24, that may be located on directional drilling assembly 70 and/or drill string 74, that may be associated with and/or utilized in extended-reach drilling operation 20, and/or that may be conveyed into the wellbore drilled by directional drilling assembly 70 and/or drill string 74. As illustrative, non-exclusive examples, pressure gauge 72 may include and/or be a downhole pressure gauge, a bottom hole pressure gauge, and/or any gauge designed to measure pressure of the wellbore and/or of subsurface region 24.

In addition, upper formations 26 and/or lower formations 28 may include and/or be any suitable subsurface formation that may include and/or contain any suitable fluid. As illustrative, non-exclusive examples, upper formations 26 and/or lower formations 28 may include a liquid, water, a liquid hydrocarbon, a gas, and/or a gaseous hydrocarbon. With this in mind, upper formations 26 also may be referred to herein as and/or may be fluid layers 26, upper fluid layers 26, fluid sands layers 26, liquid sands layers 26, gas sands layers 26, upper water-bearing layers 26, and/or water sands layers 26. Similarly, lower formations 28 also may be referred to herein as and/or may be fluid layers 28, lower fluid layers 28, fluid sands layers 28, liquid sands layers 28, gas sands layers 28, lower water-bearing layers 28, and/or aquifers 28.

FIG. 3 is a flowchart depicting methods 200 according to the present disclosure of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region. Methods 200 may include calibrating a pressure gauge at 205 and/or detecting a reference pressure at 210. Methods 200 include extending a length of the wellbore at 220 and detecting a detected pressure at a selected location within the wellbore at 225. Methods 200 further may include determining a selected depth of the selected location at 230, and methods 200 include determining an expected pressure at the selected location at 235, comparing the detected pressure to the expected pressure at 240, and adjusting an orientation of the directional drilling assembly at 245. Methods 200 further may include repeating the methods to extend the wellbore at 250, determining a target pressure within a reservoir at 255, extending the wellbore within the reservoir at 260, and/or repeating the methods to drill an additional wellbore at 265.

Calibrating the pressure gauge at 205 may include calibrating any suitable pressure gauge, or pressure gauges, that may be utilized during any suitable portion of methods 200, such as during the detecting at 210 and/or during the detecting at 225. The calibrating at 205 may be performed at any suitable time, or times, such as prior to performing a remainder of methods 200, prior to the detecting at 210, and/or prior to the detecting at 225, and may include calibrating the pressure gauge in any suitable manner and/or to any suitable accuracy and/or precision. As illustrative, non-exclusive examples, the calibrating at 205 may include calibrating to an accuracy of ±3 pounds per square inch (psi), ±2 psi, ±1.5 psi, ±1 psi, ±0.75 psi, ±0.5 psi, or ±0.25 psi at reservoir pressures.

Detecting the reference pressure at 210 may include detecting the reference pressure in any suitable manner, at any suitable location, and/or with any suitable pressure detector (or reference pressure detector). As an illustrative, non-exclusive example, the wellbore may be a second wellbore, and the detecting at 210 may include detecting the reference pressure within a first wellbore that is different from, separate from, distinct from, and/or spaced apart from the second wellbore. The first wellbore may extend within the intermediate portion of the subsurface region, may extend between the surface region and the reservoir, and/or may extend within the reservoir, and it is within the scope of the present disclosure that the detecting at 210 further may include drilling the first wellbore at 212, determining, at 214, a reference depth that corresponds to the reference pressure, and/or determining, at 216, a gas-oil contact depth and/or an oil-water contact depth within the subsurface region.

Drilling the first wellbore at 212 may include drilling the first wellbore in any suitable manner and/or using any suitable drilling assembly and/or directional drilling assembly. This may include extending a length of the first wellbore within the subsurface region, within the intermediate portion of the subsurface region, within the reservoir, and/or within one or more lower formations that may be located vertically below the reservoir, and is discussed in more detail herein.

Determining, at 214, the reference depth that corresponds to the reference pressure may include determining the reference depth in any suitable manner. As an illustrative, non-exclusive example, the detecting at 210 may include detecting the reference pressure at a reference location within the intermediate portion of the subsurface region (such as may be defined along a length of the first wellbore), and the determining at 214 may include determining the depth, or total vertical depth, of the reference location. This may include measuring the reference depth and/or calculating the reference depth, such as through the use of any suitable measurement while drilling or surveying equipment.

It is within the scope of the present disclosure that the detecting at 210 may include detecting a plurality of reference pressures at a plurality of reference locations within the subsurface region and/or within the intermediate portion thereof. Under these conditions, the determining at 214 may include determining a plurality of reference depths, with each of these reference depths corresponding to a respective one of the plurality of reference pressures (or each of the reference pressures being detected at a respective one of the plurality of reference depths).

When the detecting at 210 includes detecting a plurality of reference pressures and the determining at 214 includes determining a corresponding plurality of reference depths, methods 200 further may include determining a pressure vs. depth profile, or gradient, within the subsurface region and/or within the intermediate portion thereof. As an illustrative, non-exclusive example, the pressure vs. depth profile may be determined by fitting a curve, line, and/or a straight line to a plurality of data points that is defined by the plurality of reference pressures and the plurality of respective reference depths.

Determining, at 216, the gas-oil contact depth and/or the oil-water contact depth within the subsurface region may include determining a depth, or total vertical depth, of a gas-oil contact region, or interface, that is defined between a gas-filled region and an oil-filled region and/or determining a depth, or total vertical depth, of an oil-water contact region, or interface, that is defined between the oil-filled region and a lower water-bearing layer that may be present therebelow. This may include determining the gas-oil contact depth and/or the oil-water contact depth in any suitable manner.

As an illustrative, non-exclusive example, the drilling at 212 may include drilling the first wellbore to extend within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, and the detecting at 210 may include detecting at least one gas pressure within the gas-filled region, detecting at least one oil pressure within the oil-filled region, and detecting at least one water pressure within the lower water-bearing layer. Additionally or alternatively, the determining at 216 also may include determining a pressure vs. depth profile within the gas-filled region, within the oil-filled region, and/or within the lower water-bearing layer, such as through the use of the detected pressures within the various regions and corresponding measured depths, or total vertical depths, at which those pressures are detected.

As an illustrative, non-exclusive example, the determining at 216 may include determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region to determine the gas-oil contact depth. As another illustrative, non-exclusive example, the determining at 216 may include determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer to determine the oil-water contact depth.

Extending the length of the wellbore at 220 may include extending the length of the wellbore in any suitable manner, such as by drilling the wellbore using the directional drilling assembly. As an illustrative, non-exclusive example, the directional drilling assembly may include and/or be associated with a drill bit and/or a bottom hole assembly that includes a drill bit, and the extending at 220 may include producing cuttings at a terminal end of the wellbore with the drill bit to extend the length of the wellbore. This may include extending the length of the wellbore to locate the directional drilling assembly at the selected location within the intermediate portion of the subsurface region, which also may be referred to herein as a target location, a given location, a respective location, and/or a current location of the directional drilling assembly within the subsurface region and/or within the intermediate portion thereof.

Detecting the detected pressure at 225 may include detecting the detected pressure at the selected location and may be accomplished in any suitable manner. As an illustrative, non-exclusive example, the detecting at 225 may include detecting with any suitable pressure detector and/or pressure gauge, such as the pressure gauge that is discussed herein and/or that was calibrated during the calibrating at 205.

Determining the selected depth of the selected location at 230 may include determining the selected depth, which also may be referred to herein as the total vertical depth of the selected location, in any suitable manner. This may include measuring the selected depth and/or calculating the selected depth, such as through the use of any suitable measurement while drilling or surveying equipment.

Determining the expected pressure at the selected location at 235 may include determining the expected pressure based, at least in part, on a reference pressure that was previously detected within the subsurface region (which may include and/or be the reference pressure that is detected during the detecting at 210 and/or a reference pressure that was previously detected within the intermediate portion of the subsurface region). As an illustrative, non-exclusive example, the selected depth of the selected location may correspond to and/or equal the reference depth of the reference location. Under these conditions, the determining at 235 may include equating the expected pressure to the reference pressure.

As another illustrative, non-exclusive example, and when the detecting at 210 includes determining the pressure vs. depth profile within the intermediate portion of the subsurface region, the determining at 235 may include calculating the expected pressure from the determined pressure vs. depth profile and the selected depth that was determined during the determining at 230.

Comparing the detected pressure to the expected pressure at 240 may include comparing the detected pressure and the expected pressure in any suitable manner. As an illustrative, non-exclusive example, the comparing at 240 may include calculating a difference between the detected pressure and the expected pressure. As another illustrative, non-exclusive example, the comparing at 240 may include determining if, or that, the difference between the reference pressure and the detected pressure is greater than a threshold pressure difference.

Adjusting the orientation of the directional drilling assembly at 245 may include adjusting based, at least in part, on the comparing at 240. As an illustrative, non-exclusive example, the adjusting at 245 may include controlling, regulating, adjusting, and/or changing an orientation and/or trajectory of the wellbore with the directional drilling assembly. As an illustrative, non-exclusive example, the adjusting at 245 may include decreasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure (or less than the expected pressure by at least the threshold pressure difference). Additionally or alternatively, the adjusting at 245 also may include increasing the angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure (or greater than the expected pressure by at least the threshold pressure difference).

Additionally or alternatively, the adjusting at 245 also may include determining a magnitude of the orientation adjustment, which also may be referred to herein as an orientation adjustment magnitude. This may include calculating the orientation adjustment magnitude based, at least in part, on a magnitude of the difference between the reference pressure and the detected pressure. As an illustrative, non-exclusive example, the adjusting at 245 may include increasing the orientation adjustment magnitude proportionate to the magnitude of the difference between the reference pressure and the detected pressure.

Additionally or alternatively, the adjusting at 245 also may include calculating the orientation adjustment magnitude based, at least in part, on a fluid density. Illustrative, non-exclusive examples of the fluid density include a density of a fluid within the intermediate portion of the subsurface region, a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and/or a density of a fluid within and/or at the selected location. As an illustrative, non-exclusive example, the adjusting at 245 may include increasing the orientation adjustment magnitude proportionate to the fluid density.

Repeating the methods at 250 may include repeating any suitable portion of methods 200. As an illustrative, non-exclusive example, the repeating at 250 may include repeating the extending at 220, repeating the detecting at 225, repeating the determining at 235, repeating the comparing at 240, and repeating the adjusting at 245 a plurality of times to extend the wellbore through the intermediate portion of the subsurface region and/or from the surface region to the reservoir. As another illustrative, non-exclusive example, the repeating at 250 may include adjusting the trajectory of the wellbore a plurality of times as the wellbore is extended within the intermediate portion of the subsurface region and/or from the surface region to the reservoir.

As discussed herein, it is within the scope of the present disclosure that the intermediate portion of the subsurface region may include a plurality of upper formations, which also may be referred to herein as a plurality of intermediate formations. Under these conditions, the repeating at 250 may include detecting a respective reference pressure in each of the plurality of intermediate formations and/or in every intermediate formation that is present between the surface region and the reservoir. Additionally or alternatively, the repeating at 250 also may include repeating the extending at 220, repeating the detecting at 225, repeating the determining at 235, repeating the comparing at 240, and repeating the adjusting at 245 in at least a portion, a substantial portion, a majority, or all of the plurality of intermediate formations. Under these conditions, the determining at 235 may include determining the expected pressure in a respective formation of the plurality of formations based, at least in part, on a respective reference pressure that was detected within the respective intermediate formation.

Determining the target pressure within the reservoir at 255 may include determining the target pressure in any suitable manner. As an illustrative, non-exclusive example, methods 200 may include determining a target depth for the wellbore (or a horizontal portion thereof) within the reservoir. As an illustrative, non-exclusive example, this target depth may be based upon the determined gas-oil contact depth and/or the established oil-water contact depth (such as, for example, a midpoint between the gas-oil contact depth and the oil-water contact depth). Under these conditions, the target pressure may correspond to and/or be the pressure within the reservoir at the target depth.

Extending the wellbore within the reservoir at 260 may include extending the wellbore into and/or within the reservoir in any suitable manner. As illustrative, non-exclusive examples, the extending at 260 may include extending the length of the wellbore to locate the directional drilling assembly within the reservoir (and/or at a selected location within the reservoir) and/or detecting a reservoir pressure within the reservoir (and/or at the selected location within the reservoir). The extending at 260 further may include comparing the reservoir pressure to the target pressure and adjusting the orientation of the directional drilling assembly based, at least in part, on the comparison of the reservoir pressure to the target pressure and/or upon a difference therebetween. This may be at least substantially similar to the adjusting at 245, which is discussed in more detail herein.

As discussed herein, the systems and methods according to the present disclosure may include drilling a plurality of wells within the subsurface region. With this in mind, methods 200 further may include repeating the methods to drill an additional wellbore at 265. This may include repeating any suitable portion of methods 200 any suitable number of times to drill any suitable number of additional wellbores within the subsurface region, within the intermediate portion of the subsurface region, between the surface region and the reservoir, and/or within the reservoir.

As an illustrative, non-exclusive example, the repeating at 265 may include repeating at least the extending at 220, the detecting at 225, the determining at 235, the comparing at 240, and the adjusting at 245 to drill a subsequent wellbore of the plurality of wellbores. As another illustrative, non-exclusive example, the repeating at 265 also may include repeating the detecting at 210 a plurality of times while drilling the plurality of wellbores and using the detected reference pressures from a given wellbore when drilling one or more subsequent wellbores of the plurality of wellbores.

In the present disclosure, several of the illustrative, non-exclusive examples have been discussed and/or presented in the context of flow diagrams, or flow charts, in which the methods are shown and described as a series of blocks, or steps. Unless specifically set forth in the accompanying description, it is within the scope of the present disclosure that the order of the blocks may vary from the illustrated order in the flow diagram, including with two or more of the blocks (or steps) occurring in a different order and/or concurrently. It is also within the scope of the present disclosure that the blocks, or steps, may be implemented as logic, which also may be described as implementing the blocks, or steps, as logics. In some applications, the blocks, or steps, may represent expressions and/or actions to be performed by functionally equivalent circuits or other logic devices. The illustrated blocks may, but are not required to, represent executable instructions that cause a computer, processor, and/or other logic device to respond, to perform an action, to change states, to generate an output or display, and/or to make decisions.

As used herein, the term “and/or” placed between a first entity and a second entity means one of (1) the first entity, (2) the second entity, and (3) the first entity and the second entity. Multiple entities listed with “and/or” should be construed in the same manner, i.e., “one or more” of the entities so conjoined. Other entities may optionally be present other than the entities specifically identified by the “and/or” clause, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, a reference to “A and/or B,” when used in conjunction with open-ended language such as “comprising” may refer, in one embodiment, to A only (optionally including entities other than B); in another embodiment, to B only (optionally including entities other than A); in yet another embodiment, to both A and B (optionally including other entities). These entities may refer to elements, actions, structures, steps, operations, values, and the like.

As used herein, the phrase “at least one,” in reference to a list of one or more entities should be understood to mean at least one entity selected from any one or more of the entity in the list of entities, but not necessarily including at least one of each and every entity specifically listed within the list of entities and not excluding any combinations of entities in the list of entities. This definition also allows that entities may optionally be present other than the entities specifically identified within the list of entities to which the phrase “at least one” refers, whether related or unrelated to those entities specifically identified. Thus, as a non-limiting example, “at least one of A and B” (or, equivalently, “at least one of A or B,” or, equivalently “at least one of A and/or B”) may refer, in one embodiment, to at least one, optionally including more than one, A, with no B present (and optionally including entities other than B); in another embodiment, to at least one, optionally including more than one, B, with no A present (and optionally including entities other than A); in yet another embodiment, to at least one, optionally including more than one, A, and at least one, optionally including more than one, B (and optionally including other entities). In other words, the phrases “at least one,” “one or more,” and “and/or” are open-ended expressions that are both conjunctive and disjunctive in operation. For example, each of the expressions “at least one of A, B and C,” “at least one of A, B, or C,” “one or more of A, B, and C,” “one or more of A, B, or C” and “A, B, and/or C” may mean A alone, B alone, C alone, A and B together, A and C together, B and C together, A, B and C together, and optionally any of the above in combination with at least one other entity.

In the event that any patents, patent applications, or other references are incorporated by reference herein and (1) define a term in a manner that is inconsistent with and/or (2) are otherwise inconsistent with, either the non-incorporated portion of the present disclosure or any of the other incorporated references, the non-incorporated portion of the present disclosure shall control, and the term or incorporated disclosure therein shall only control with respect to the reference in which the term is defined and/or the incorporated disclosure was present originally.

As used herein the terms “adapted” and “configured” mean that the element, component, or other subject matter is designed and/or intended to perform a given function. Thus, the use of the terms “adapted” and “configured” should not be construed to mean that a given element, component, or other subject matter is simply “capable of” performing a given function but that the element, component, and/or other subject matter is specifically selected, created, implemented, utilized, programmed, and/or designed for the purpose of performing the function. It is also within the scope of the present disclosure that elements, components, and/or other recited subject matter that is recited as being adapted to perform a particular function may additionally or alternatively be described as being configured to perform that function, and vice versa.

Illustrative, non-exclusive examples of systems and methods according to the present disclosure are presented in the following enumerated paragraphs. It is within the scope of the present disclosure that an individual step of a method recited herein, including in the following enumerated paragraphs, may additionally or alternatively be referred to as a “step for” performing the recited action.

A1. A method of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region, wherein the intermediate portion of the subsurface region extends between a surface region and a reservoir that is present within the subsurface region, the method comprising: extending a length of the wellbore to locate the directional drilling assembly at a selected location within the intermediate portion of the subsurface region; detecting a detected pressure at the selected location; determining an expected pressure at the selected location, wherein the determining is based, at least in part, on a reference pressure that was previously detected within the subsurface region, and optionally within the intermediate portion of the subsurface region; comparing the detected pressure to the expected pressure; and adjusting an orientation of the directional drilling assembly based, at least in part, on the comparing. A2. The method of paragraph A1, wherein the method further includes detecting the reference pressure. A3. The method of paragraph A2, wherein the wellbore is a second wellbore, and further wherein the detecting the reference pressure includes detecting the reference pressure within a first wellbore that extends within the intermediate portion of the subsurface region, wherein the first wellbore is spaced apart from the second wellbore. A4. The method of any of paragraphs A2-A3, wherein the detecting the reference pressure includes drilling a/the first wellbore within the subsurface region. A5. The method of any of paragraphs A2-A4, wherein the detecting the reference pressure includes detecting the reference pressure at a reference location within the intermediate portion of the subsurface region, and further wherein the method includes determining a reference depth of the reference location. A6. The method of paragraph A5, wherein the determining the reference depth includes at least one of measuring the reference depth and calculating the reference depth. A7. The method of any of paragraphs A5-A6, wherein the determining a reference depth includes measuring the reference depth via a measurement while drilling survey. A8. The method of any of paragraphs A2-A7, wherein the detecting the reference pressure includes detecting a plurality of reference pressures at a plurality of reference locations within the intermediate portion of the subsurface region, and further wherein the method includes determining a plurality of reference depths of the plurality of reference locations, wherein each of the plurality of reference pressures is detected at a respective one of the plurality of reference depths. A9. The method of any of paragraphs A2-A8, wherein the detecting the reference pressure further includes determining a pressure vs. depth profile within the intermediate portion of the subsurface region. A10. The method of paragraph A9, wherein the pressure vs. depth profile is determined by fitting at least one of a curve, a line and a straight line to a plurality of data points that is defined by a/the plurality of reference pressures and a/the plurality of reference depths. A11. The method of any of paragraphs A1-A10, wherein the directional drilling assembly includes a drill bit, and further wherein the extending includes producing cuttings at a terminal end of the wellbore with the drill bit to extend the length of the wellbore. A12. The method of any of paragraphs A1-A11, wherein the directional drilling assembly includes a pressure gauge, and further wherein the detecting the detected pressure includes detecting the detected pressure with the pressure gauge. A13. The method of paragraph A12, wherein the method further includes calibrating the pressure gauge, optionally prior to performing a remainder of the method. A14. The method of paragraph A13, wherein the calibrating includes calibrating the pressure gauge to an accuracy of ±3 pounds per square inch (psi), ±2 psi, ±1.5 psi, ±1 psi, ±0.75 psi, ±0.5 psi, or ±0.25 psi. A15. The method of any of paragraphs A1-A14, wherein the method further includes determining a selected depth of the selected location. A16. The method of paragraph A15, wherein the determining the selected depth includes at least one of measuring the selected depth and calculating the selected depth. A17. The method of any of paragraphs A15-A16, wherein the determining the selected depth includes measuring the selected depth via a measurement while drilling survey. A18. The method of any of paragraphs A15-A17, when dependent from paragraph A2, wherein the detecting the reference pressure includes detecting the reference pressure at a/the reference location within the intermediate portion of the subterranean formation that defines a/the reference depth within the subterranean formation, wherein the reference depth is equal to the selected depth, and further wherein the determining the expected pressure includes equating the expected pressure to the reference pressure. A19. The method of any of paragraphs A15-A17, when dependent from paragraph A2, wherein the detecting the reference pressure includes determining a/the pressure vs. depth profile within the intermediate portion of the subsurface region. A20. The method of paragraph A1, wherein the determining the expected pressure includes calculating the expected pressure from the determined pressure vs. depth profile within the intermediate portion of the subsurface region and the determined selected depth of the selected location. A21. The method of any of paragraphs A1-A20, wherein the comparing includes calculating a/the difference between the measured pressure and the reference pressure. A22. The method of paragraph A21, wherein the comparing includes determining that the difference between the reference pressure and the detected pressure is greater than a threshold pressure difference. A23. The method of any of paragraphs A1-A22, wherein the adjusting includes controlling an orientation of the wellbore with the directional drilling assembly. A24. The method of any of any of paragraphs A1-A23, wherein the adjusting includes adjusting a trajectory of the wellbore. A25. The method of any of paragraphs A1-A24, wherein the adjusting includes increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure. A26. The method of any of paragraphs A1-A25, wherein the adjusting includes decreasing an/the angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure. A27. The method of any of paragraphs A1-A26, wherein the adjusting further includes determining an orientation adjustment magnitude. A28. The method of paragraph A27, wherein the determining the orientation adjustment magnitude includes calculating the orientation adjustment magnitude based, at least in part, on a magnitude of a/the difference between the reference pressure and the detected pressure. A29. The method of any of paragraphs A27-A28, wherein the determining the orientation adjustment magnitude includes increasing the orientation adjustment magnitude proportionate to a/the magnitude of a/the difference between the reference pressure and the detected pressure. A30. The method of any of paragraphs A27-A29, wherein the determining the orientation adjustment magnitude includes calculating the orientation adjustment magnitude based, at least in part, on at least one of (i) a density of a fluid within the intermediate portion of the subsurface region, (ii) a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and (iii) a density of a fluid within the intermediate portion of the subsurface region that is at the selected location. A31. The method of any of paragraphs A27-A30, wherein the determining the orientation adjustment magnitude includes increasing the orientation adjustment magnitude proportionate to at least one of (i) a density of a fluid within the intermediate portion of the subsurface region, (ii) a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and (iii) a density of a fluid within the intermediate portion of the subsurface region that is at the selected location. A32. The method of any of paragraphs A1-A31, wherein the method further includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting a plurality of times to extend the wellbore through the intermediate region and from the surface region to the reservoir. A33. The method of paragraph A32, wherein the repeating includes adjusting a/the trajectory of the wellbore a plurality of times. A34. The method of any of paragraphs A1-A33, wherein the intermediate portion of the subsurface region includes a plurality of intermediate formations, and further wherein the method includes detecting a respective reference pressure in each of the plurality of intermediate formations, and optionally in every intermediate formation that is present between the surface region and the reservoir. A35. The method of paragraph A34, wherein the method includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting in each of the plurality of intermediate formations. A36. The method of paragraph A35, wherein the determining the expected pressure includes determining the expected pressure in a respective intermediate formation of the plurality of intermediate formations based, at least in part, on the respective reference pressure that was detected within the respective intermediate formation. A37. The method of any of paragraphs A1-A36, wherein the method further includes extending the wellbore within the reservoir. A38. The method of paragraph A37, wherein the reservoir defines a gas-filled region, an oil-filled region, and a gas-oil contact region, wherein a lower water-bearing layer is located vertically below the oil-filled region and defines an oil-water contact region, and further wherein, prior to the extending, the method further includes determining a gas-oil contact depth of the gas-oil contact region and determining an oil-water contact depth of the oil-water contact region. A39. The method of paragraph A38, wherein the wellbore is a/the second wellbore, wherein the detecting the reference pressure includes detecting the reference pressure within a/the first wellbore that extends within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, and further wherein the first wellbore is spaced apart from the second wellbore. A40. The method of paragraph A39, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes detecting at least one gas pressure, and optionally a plurality of gas pressures, within the gas-filled region, detecting at least one oil pressure, and optionally a plurality of oil pressures, within the oil-filled region, and detecting at least one water pressure, and optionally a plurality of water pressures, within the lower water-bearing layer. A41. The method of paragraph A40, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes determining a pressure vs. depth profile within the gas-filled region, determining a pressure vs. depth profile within the oil-filled region, and determining a pressure vs. depth profile within the lower water-bearing layer. A42. The method of paragraph A41, wherein the determining the gas-oil contact depth includes determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region. A43. The method of any of paragraphs A41-A42, wherein the determining the oil-water contact depth includes determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer. A44. The method of any of paragraphs A38-A43, wherein the method further includes determining a target depth for the wellbore within the reservoir, wherein the target depth is based, at least in part, on the gas-oil contact depth and the oil-water contact depth, and further wherein the method includes determining a target pressure within the reservoir at the target depth. A45. The method of paragraph A44, wherein the method further includes:

(i) extending the length of the wellbore to locate the directional drilling assembly within the reservoir;

(ii) detecting a reservoir pressure within the reservoir;

(iii) comparing the reservoir pressure to the target pressure; and

(iv) adjusting the orientation of the directional drilling assembly based, at least in part, on the comparing the reservoir pressure to the target pressure.

A46. An extended-reach drilling operation, comprising:

a directional drilling assembly; and

a controller that is programmed to control the operation of the directional drilling assembly using the method of any of paragraphs A1-A45.

A47. The drilling operation of paragraph A46, wherein the drilling operation further includes a wellbore that extends between a surface region and a reservoir that is present within a subsurface region. A48. The drilling operation of paragraph A47, wherein the drilling operation further includes the reservoir. B1. The use of any of the methods of any of paragraphs A1-A45 or any of the drilling operations of any of paragraphs A46-A48 to drill an extended-reach well. B2. The use of pressure measurements to adjust an orientation of a directional drilling assembly to control a trajectory of a wellbore that extends within an intermediate portion of a subsurface region that is located between a surface region and a wellbore. B3. A wellbore constructed using the method of any of paragraphs A1-A48. B4. Hydrocarbons produced from the wellbore of paragraph B3. B5. A well that includes the wellbore of paragraph B3. B6. Hydrocarbons produced using the method of any of paragraphs A1-A48 PCT1. A method of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region, wherein the intermediate portion of the subsurface region extends between a surface region and a reservoir that is present within the subsurface region, the method comprising: extending a length of the wellbore to locate the directional drilling assembly at a selected location within the intermediate portion of the subsurface region; detecting a detected pressure at the selected location; determining an expected pressure at the selected location, wherein the determining is based, at least in part, on a reference pressure that was previously detected within the intermediate portion of the subsurface region; comparing the detected pressure to the expected pressure; and adjusting an orientation of the directional drilling assembly based, at least in part, on the comparing. PCT2. The method of paragraph PCT1, wherein the method further includes detecting the reference pressure. PCT3. The method of paragraph PCT2, wherein the wellbore is a second wellbore, and further wherein the detecting the reference pressure includes detecting the reference pressure within a first wellbore that extends within the intermediate portion of the subsurface region, wherein the first wellbore is spaced apart from the second wellbore. PCT4. The method of any of paragraphs PCT2-PCT3, wherein the detecting the reference pressure includes detecting the reference pressure at a reference location within the intermediate portion of the subsurface region, and further wherein the method includes determining a reference depth of the reference location. PCT5. The method of any of paragraphs PCT2-PCT4, wherein the detecting the reference pressure includes detecting a plurality of reference pressures at a plurality of reference locations within the intermediate portion of the subsurface region, and further wherein the method includes determining a plurality of reference depths of the plurality of reference locations, wherein each of the plurality of reference pressures is detected at a respective one of the plurality of reference depths. PCT6. The method of any of paragraphs PCT2-PCT5, wherein the method further includes determining a selected depth of the selected location. PCT7. The method of paragraph PCT6, wherein the detecting the reference pressure includes detecting the reference pressure at a/the reference location within the intermediate portion of the subsurface region that defines a/the reference depth within the subsurface region, wherein the reference depth is equal to the selected depth, and further wherein the determining the expected pressure includes equating the expected pressure to the reference pressure. PCT8. The method of any of paragraphs PCT6-PCT7, wherein the detecting the reference pressure includes determining a pressure vs. depth profile within the intermediate portion of the subsurface region, and further wherein the determining the expected pressure includes calculating the expected pressure from the determined pressure vs. depth profile within the intermediate portion of the subsurface region and the determined selected depth of the selected location. PCT9. The method of any of paragraphs PCT1-PCT8, wherein the adjusting includes at least one of:

(i) increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure; and

(ii) decreasing the angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure.

PCT10. The method of any of paragraphs PCT1-PCT9, wherein the adjusting further includes determining an orientation adjustment magnitude, wherein the determining the orientation adjustment magnitude includes at least one of:

(i) calculating the orientation adjustment magnitude based, at least in part, on a magnitude of a difference between the reference pressure and the detected pressure; and

(ii) increasing the orientation adjustment magnitude proportionate to a magnitude of the difference between the reference pressure and the detected pressure.

PCT11. The method of any of paragraphs PCT1-PCT10, wherein the method further includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting a plurality of times to extend the wellbore through the intermediate portion and from the surface region to the reservoir. PCT12. The method of any of paragraphs PCT1-PCT11, wherein the method further includes extending the wellbore within the reservoir, wherein the reservoir defines a gas-filled region, an oil-filled region, and a gas-oil contact region, wherein a lower water-bearing layer is located vertically below the oil-filled region and defines an oil-water contact region, and further wherein, prior to the extending, the method further includes determining a gas-oil contact depth of the gas-oil contact region and determining an oil-water contact depth of the oil-water contact region. PCT13. The method of paragraph PCT12, wherein the wellbore is a/the second wellbore, wherein the detecting the reference pressure includes detecting the reference pressure within a/the first wellbore that extends within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, wherein the first wellbore is spaced apart from the second wellbore, and further wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes detecting at least one gas pressure within the gas-filled region, detecting at least one oil pressure within the oil-filled region, and detecting at least one water pressure within the lower water-bearing layer, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes determining a pressure vs. depth profile within the gas-filled region, determining a pressure vs. depth profile within the oil-filled region, and determining a pressure vs. depth profile within the lower water-bearing layer, wherein the determining the gas-oil contact depth includes determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region, and further wherein the determining the oil-water contact depth includes determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer. PCT14. The method of paragraph PCT13, wherein the method further includes determining a target depth for the wellbore within the reservoir, wherein the target depth is based, at least in part, on the gas-oil contact depth and the oil-water contact depth, and further wherein the method includes determining a target pressure within the reservoir at the target depth. PCT15. The method of paragraph PCT14, wherein the method further includes:

(i) extending the length of the wellbore to locate the directional drilling assembly within the reservoir;

(ii) detecting a reservoir pressure within the reservoir;

(iii) comparing the reservoir pressure to the target pressure; and

(iv) adjusting the orientation of the directional drilling assembly based, at least in part, on the comparing the reservoir pressure to the target pressure.

INDUSTRIAL APPLICABILITY

The systems and methods disclosed herein are applicable to the oil and gas industry.

It is believed that the disclosure set forth above encompasses multiple distinct inventions with independent utility. While each of these inventions has been disclosed in its preferred form, the specific embodiments thereof as disclosed and illustrated herein are not to be considered in a limiting sense as numerous variations are possible. The subject matter of the inventions includes all novel and non-obvious combinations and subcombinations of the various elements, features, functions and/or properties disclosed herein. Similarly, where the claims recite “a” or “a first” element or the equivalent thereof, such claims should be understood to include incorporation of one or more such elements, neither requiring nor excluding two or more such elements.

It is believed that the following claims particularly point out certain combinations and subcombinations that are directed to one of the disclosed inventions and are novel and non-obvious. Inventions embodied in other combinations and subcombinations of features, functions, elements and/or properties may be claimed through amendment of the present claims or presentation of new claims in this or a related application. Such amended or new claims, whether they are directed to a different invention or directed to the same invention, whether different, broader, narrower, or equal in scope to the original claims, are also regarded as included within the subject matter of the inventions of the present disclosure. 

1. A method of controlling a directional drilling assembly that is configured to drill a wellbore within an intermediate portion of a subsurface region, wherein the intermediate portion of the subsurface region extends between a surface region and a reservoir that is present within the subsurface region, the method comprising: extending a length of the wellbore to locate the directional drilling assembly at a selected location within the intermediate portion of the subsurface region; detecting a detected pressure at the selected location; determining an expected pressure at the selected location, wherein the determining is based, at least in part, on a reference pressure that was previously detected within the intermediate portion of the subsurface region; comparing the detected pressure to the expected pressure; and adjusting an orientation of the directional drilling assembly based, at least in part, on the comparing.
 2. The method of claim 1, wherein the method further includes detecting the reference pressure.
 3. The method of claim 2, wherein the wellbore is a second wellbore, and further wherein the detecting the reference pressure includes detecting the reference pressure within a first wellbore that extends within the intermediate portion of the subsurface region, wherein the first wellbore is spaced apart from the second wellbore.
 4. The method of claim 2, wherein the detecting the reference pressure includes detecting the reference pressure at a reference location within the intermediate portion of the subsurface region, and further wherein the method includes determining a reference depth of the reference location.
 5. The method of claim 2, wherein the detecting the reference pressure includes detecting a plurality of reference pressures at a plurality of reference locations within the intermediate portion of the subsurface region, and further wherein the method includes determining a plurality of reference depths of the plurality of reference locations, wherein each of the plurality of reference pressures is detected at a respective one of the plurality of reference depths.
 6. The method of claim 2, wherein the detecting the reference pressure further includes determining a pressure vs. depth profile within the intermediate portion of the subsurface region.
 7. The method of claim 2, wherein the method further includes determining a selected depth of the selected location.
 8. The method of claim 7, wherein the detecting the reference pressure includes detecting the reference pressure at a reference location within the intermediate portion of the subsurface region that defines a reference depth within the subsurface region, wherein the reference depth is equal to the selected depth, and further wherein the determining the expected pressure includes equating the expected pressure to the reference pressure.
 9. The method of claim 7, wherein the detecting the reference pressure includes determining a pressure vs. depth profile within the intermediate portion of the subsurface region, and further wherein the determining the expected pressure includes calculating the expected pressure from the determined pressure vs. depth profile within the intermediate portion of the subsurface region and the determined selected depth of the selected location.
 10. The method of claim 1, wherein the comparing includes calculating a difference between a measured pressure and the reference pressure.
 11. The method of claim 10, wherein the comparing includes determining that the difference between the reference pressure and the detected pressure is greater than a threshold pressure difference.
 12. The method of claim 1, wherein the adjusting includes adjusting a trajectory of the wellbore with the directional drilling assembly.
 13. The method of claim 1, wherein the adjusting includes at least one of: (i) increasing an angle of inclination of the directional drilling assembly responsive to the detected pressure being greater than the expected pressure; and (ii) decreasing the angle of inclination of the directional drilling assembly responsive to the detected pressure being less than the expected pressure.
 14. The method of claim 1, wherein the adjusting further includes determining an orientation adjustment magnitude.
 15. The method of claim 14, wherein the determining the orientation adjustment magnitude includes calculating the orientation adjustment magnitude based, at least in part, on a magnitude of a difference between the reference pressure and the detected pressure.
 16. The method of claim 14, wherein the determining the orientation adjustment magnitude includes increasing the orientation adjustment magnitude proportionate to a magnitude of a difference between the reference pressure and the detected pressure.
 17. The method of claim 14, wherein the determining the orientation adjustment magnitude includes calculating the orientation adjustment magnitude based, at least in part, on at least one of (i) a density of a fluid within the intermediate portion of the subsurface region, (ii) a density of a fluid within the intermediate portion of the subsurface region that is proximate to the selected location, and (iii) a density of a fluid within the intermediate portion of the subsurface region that is at the selected location.
 18. The method of claim 1, wherein the method further includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting a plurality of times to extend the wellbore through the intermediate portion and from the surface region to the reservoir.
 19. The method of claim 1, wherein the intermediate portion of the subsurface region includes a plurality of intermediate formations, and further wherein the method includes detecting a respective reference pressure in each of the plurality of intermediate formations.
 20. The method of claim 19, wherein the method includes repeating the extending, the detecting the detected pressure, the determining the expected pressure, the comparing, and the adjusting in each of the plurality of intermediate formations, and further wherein the determining the expected pressure includes determining the expected pressure in a respective intermediate formation of the plurality of intermediate formations based, at least in part, on the respective reference pressure that was detected within the respective intermediate formation.
 21. The method of claim 1, wherein the method further includes extending the wellbore within the reservoir.
 22. The method of claim 21, wherein the reservoir defines a gas-filled region, an oil-filled region, and a gas-oil contact region, wherein a lower water-bearing layer is located vertically below the oil-filled region and defines an oil-water contact region, and further wherein, prior to the extending, the method further includes determining a gas-oil contact depth of the gas-oil contact region and determining an oil-water contact depth of the oil-water contact region.
 23. The method of claim 22, wherein the wellbore is a second wellbore, wherein the detecting the reference pressure includes detecting the reference pressure within a first wellbore that extends within the gas-filled region, within the oil-filled region, and within the lower water-bearing layer, wherein the first wellbore is spaced apart from the second wellbore, and further wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes detecting at least one gas pressure within the gas-filled region, detecting at least one oil pressure within the oil-filled region, and detecting at least one water pressure within the lower water-bearing layer.
 24. The method of claim 23, wherein the determining the gas-oil contact depth and the determining the oil-water contact depth includes determining a pressure vs. depth profile within the gas-filled region, determining a pressure vs. depth profile within the oil-filled region, and determining a pressure vs. depth profile within the lower water-bearing layer, wherein the determining the gas-oil contact depth includes determining an intersection point between the pressure vs. depth profile within the gas-filled region and the pressure vs. depth profile within the oil-filled region, and further wherein the determining the oil-water contact depth includes determining an intersection point between the pressure vs. depth profile within the oil-filled region and the pressure vs. depth profile within the lower water-bearing layer.
 25. The method of claim 22, wherein the method further includes determining a target depth for the wellbore within the reservoir, wherein the target depth is based, at least in part, on the gas-oil contact depth and the oil-water contact depth, and further wherein the method includes determining a target pressure within the reservoir at the target depth.
 26. The method of claim 25, wherein the method further includes: (i) extending the length of the wellbore to locate the directional drilling assembly within the reservoir; (ii) detecting a reservoir pressure within the reservoir; (iii) comparing the reservoir pressure to the target pressure; and (iv) adjusting the orientation of the directional drilling assembly based, at least in part, on the comparing the reservoir pressure to the target pressure.
 27. An extended-reach drilling operation, comprising: a reservoir that is present within a subsurface region; a wellbore that extends between a surface region and the reservoir; a directional drilling assembly; and a controller that is programmed to control the operation of the directional drilling assembly using the method of claim
 1. 